The present invention relates to radioactivity well logging and, more particularly, to a method using natural gamma ray logging for in situ determination of the cation exchange capacity of subsurface formations traversed by a borehole.
The evaluation of petroleum reservoirs requires the knowledge of several fundamental reservoir properties. One such property of particular importance is water saturation, Sw. In a typical oil field, water, called interstitial water, and frequently free gas are present in addition to oil. Water saturation is that portion of the subsurface formation pore volume, also called porosity of the formation, which is occupied by interstitial water. The fraction of the formation pore volume not occupied by interstitial water is said to be occupied by hydrocarbons. Oil, condensate or gas in place will vary directly with the equation, (1-Sw), where Sw is the interstitial water expressed as a fraction of porosity and generally will vary inversely with porosity. Thus, with a decrease in porosity water saturation will increase and with an increase in porosity, water saturation will decrease, with a concurrent opposite change in oil and gas saturation.
In addition to indicating the relative volume occupied by formation water, Sw serves as an indication of hydrocarbon recovery difficulties. The amount of water saturation in the formation will assist in determining the ease with which oil moves through rock. There will be a greater resistance to the flow of hydrocarbons through formations containing 60% water saturation than through the same formations in which water saturation is low, since interstitial water will block some of the flow channels in the formation. Only where water saturation is low, say less than 40% of total pore volume, will oil and gas saturation be sufficient to have producing formations.
Early prior art method for determining water saturation and thus hydrocarbon saturation of formations consisted of laboratory analysis of formation samples. These methods required formation coring and subsequent treating of the recovered cores which treatment can cause great changes in water and hydrocarbon content. True proporportions of the various fluids originally present cannot be obtained by analysis of a core that contains drilling fluid. Additionally, obtaining core samples from subterranean formations is a time consuming and costly undertaking since a large number of samples is required.
Due to problems encountered with attempts to determine water saturation from core samples, a number of interpretive concepts have been developed for indirectly estimating water saturation. The majority of these interpretive techniques have proven less than accurate over the entire range of formation conditions. Varying salinity and shale conditions encountered in the samples have presented particular problems.
It has been determined that there are very few oil-producing sands that are entirely free of clay minerals. The term shaly sand is used to describe reservoir rock having a clay content above five percent. Clay as a rock form is difficult to define precisely because of the wide variety of clay-grade material which may consist of varying relative amount of non-clay and clay mineral components. Non-clay materials include calcite, dolomite, large flakes of mica, pyrite, feldspar, gibbsite and other minerals. Generally, fine grained materials have been called "clay" so long as they had distinct plasticity and insufficient amounts of coarser material. Some clay materials found in subsurface formations are smectite, illite, kaolinite and chlorite.
Since clay minerals are abundant throughout sedimentary columns, all formation log readings must be corrected for the effects of the clay. Clay corrections assume that the clay deposited during the various phases of a continuous sedimentation cycle has the same composition throughout the complete cycle. By assuming that the clay materials are all equivalent, clay corrections can more easily be calculated and applied. However, results have been found to be unrealistic under some formation conditions resulting in appraisal which have been too pessimistic in some zones and which may condemn some zones of commercial significance.
An additional failing of prior interpretive concepts is that most of these techniques do not take into account the fact that the influence of clay minerals on formation measurements are non-linear. It has been found that formation resistivity will become progressively greater in a non-linear fashion as the formation water becomes fresher. This non-linear relation is because the effective concentration of clay-exchange cations increases in proportion to decreases in water saturation.
Cation exchange is the reaction whereby hydrated positively charged ions of a solid, such as clay, are exchanged, equivalent for equivalent, for cations of like charge in saturation. A physical model well known in the art describing shaly sand conductivities which accounts for dispersed clay in hydrocarbon bearing shaly sand formations is: ##EQU1## where:
Sw=percent of water saturation
n*=saturation exponent
Rt=formation resistivity
F*=formation resistivity factor
Rw=formation water resistivity
B=equivalent conductance of clay exchange cations as a function of Rw
Qv=concentration of counter ions in the formation water in contact with the clay.
Basically the model describes the resistivity, or the reciprocal conductivity, of shaly sands as a function of the salinity concentration and amount of formation water occupying pore space; the concentration and mobility of exchangeable cations associated with the various clay minerals; and, formation temperature. Accepted experimental data indicates that this physical model allows for improved analysis in shaly sand formations, over the entire salinity range encountered in potential reservoir rocks.
The historical problem with the above physical model is in obtaining a value fo the concentration of counter ions (Qv) in the formation water in contact with the clay. Qv can be calculated from the cation exchange capacity, porosity and grain matrix density. Expressed mathematically: EQU Qv=CEC.multidot.(1-.phi.).multidot..rho.ma.multidot..phi..sup.-1 ( 2)
where,
CEC=cation exchange capacity
.phi.=porosity
.rho.ma=grain matrix density
Porosity and grain matrix density are determined by the results derived from well logging data well known in the art. However, in the art, the remaining term, CEC, is determined by taking formation core samples from each well evaluated. This core sampling process has the liabilities discussed heretofore. Although tedious, costly and time consuming, coring is used to establish an empirical relationship between porosity (.phi.) and the concentration of counter ions (Qv) in the formation in contact with clay to derive a normalized term relating to Cation Exchange Capacity. However, this approach has many limitations. The limitations include porosity variations due to grain size changes and the amount of cementation, all of which are independent of shaliness, clay content, and thus Qv variations.
Accordingly, the present invention overcomes the deficiencies of the prior art by providing a method for utilizing information derived from a correlation of core sample data from a single borehole with information derived from the natural gamma ray well logging of that borehole to establish a relationship which can be utilized in subsequent boreholes to estimate the cation exchange capacity of formations surrounding the borehole.